Hydrocarbon recovery wells for producing oil and gas involve using long tubing strings to convey the hydrocarbons from the downhole reservoir to the surface. In many instances it is desirable to maintain temperature and minimize heat loss from substances flowing through the string. In more conventional oil recovery operations, the oil may already be highly flowable within the reservoir. Nevertheless, because the viscosity of oil increases as it cools, minimizing heat loss helps the oil maintain flowability, making it easier and less costly to produce.
In some recovery operations, however, oil may be very viscous within the reservoir. It may then be necessary to heat the oil downhole in order to produce it in economically viable quantities. Minimizing heat loss in the string is therefore more critical. In these situations, hot steam is typically passed downhole through the tubing string to release the thickened or trapped oil so it becomes flowable. Insulated tubing strings minimize heat loss from the steam and oil.
An older method of insulating a tubular assembly involved applying insulation to the outside of a tubing string, such as described in U.S. Pat. No. 3,763,935. The insulation extended from the earth's surface down to the bottom of the permafrost zone, in a continuous cylindrical form. This method of insulation had several disadvantages, however. Applying thermal insulation in this manner was expensive and time consuming. The insulation was also quite fragile under typical drilling conditions.
A newer category of insulated tubing strings involves stringing together double-walled insulated tubing segments. Generally, each insulated tubing segment has an outer tube disposed about an inner tube and defining an annular space therebetween. The annular space is sometimes filled with insulating material. Alternatively, a vacuum may be established in the annulus to insulate the tubing. Heat transfer is therefore minimized between the inner wall, which may be exposed to hot oil and steam, and the outer wall, which may be exposed to the cooler interior of the well bore or to atmosphere. U.S. Pat. No. 4,512,721, for example, discloses insulated tubing having a vacuum annulus filled with a “getter material” for absorbing gases that can migrate into the annulus at high temperatures. U.S. Pat. No. 3,680,631 discloses insulated tubing combining the use of vacuum and solid thermal insulation, for passing warm fluids through a permafrost zone.
Despite their increased durability and ease of assembly, the use of insulated tubing segments has inherent disadvantages. A major problem with joining insulated tubing segments is that excessive heat loss may occur at the joint between segments. This is because an insulated segment is not insulated at its ends where the outer tube is joined with the inner tube to seal the annulus between the inner and outer tube. Heat may therefore be conducted away from the interior of the tubing along a conductive flow path at each joint, at a much higher rate than through the insulated portion of the tube. This results in greater heat loss and reduced efficiency.
A number of solutions have been proposed to minimize heat loss at the joint between insulated tubing segments. U.S. Pat. No. 4,518,175 discloses an insulated tubular assembly having insulation underneath an external coupler at the tubing joint. A frustoconical member supports and positions the inner pipe relative to the outer pipe of each tubing segment. The frustoconical member extends diagonally upward from an end of the inner tube to an adjacent end of the outer tube. The insulation at the joint is layered between the external coupler and the frustoconical member, and extends over a portion of the insulated tubing annulus. The overlapping annulus insulation and joint insulation essentially provides continuous insulation along the tubular assembly, minimizing heat loss at the joint.
U.S. Pat. No. 4,415,184 discloses an insulated tubular assembly having insulation between an external coupling and the insulated tubing segments at the tubing joint. A fluid-tight thrust ring seals and joins adjacent ends of the inner and outer tubes of each tubing segment. Insulation is sandwiched between the thrust rings and the external coupler that couples two insulated tubing segments. The insulation may be cast in place during manufacture of the tubing segments, or inserted during installation of the tubular assembly. An additional ring of insulation must be inserted at the joint between the ends of the tubing segments to provide continuous insulation along the joint.
Yet another way of insulating the joint internal to a coupler is provided by U.S. Pat. No. 4,693,313. An external coupler joins two tubing segments, leaving a substantial gap between the joined ends. The gap created between the coupled segments is insulated by means of a coupling insulator, which typically includes suitable insulation material. A tubular shield is positioned inside the coupling insulator to shield the joint insulation material from fluids passing through the tubular assembly.
A different approach to insulating the joint is provided by U.S. Pat. No. 4,538,834. The tubing segments are joined with only a slight gap or space left between them at the joint. Condensate of the fluid flowing through the assembly is trapped in the space, which may form a thermal barrier between the fluid flowing through the assembly and the ambient environment.
The above insulating tubing joints and methods have the drawback that the insulation at the joint is fitted internal to the coupler. Applying insulation during the manufacture of each tubing segment in this way can be complicated and expensive. For example, the insulation must be installed so the coupler will later fit around it when joining two insulated tubing segments. If the coupler does not fit properly during installation, it may not be correctable in the field during installation, while away from the manufacturing facility. If the insulation is instead applied in the field during installation, this can be a complicated or time-consuming step.
Another complication with the above tubing joints is that it may be difficult or impossible to repair or replace the insulation once in the field. The joint will most likely have to be disassembled to access the insulation. Whether the insulation needs replacement may be difficult or impossible to discern, because it is hidden within the joint. Especially in a long tubing string, a great deal of effort is required to break apart each joint whose insulation needs inspection or repair.
A further disadvantage of having insulation on the inside of a coupler of a joint is that the flow through the tubular assembly may be disrupted. For example, the tubular assembly of U.S. Pat. No. 4,693,313 requires installing a shield to prevent flow within the inner tube from impinging the joint insulation. Even with this extra step, the shield might impede the flow or cause turbulent flow.
The disadvantages of the prior art are overcome by the present invention. An insulated tubular assembly is provided having an improved insulated joint that is easier and less expensive to manufacture, install, repair, and replace.